1. Field of the Invention
This invention relates to a method and apparatus for determining the permeability and/or porosity of a gas-containing substrate.
2. Description of the Related Art
Subsurface deposits of gas and oil are generally trapped in porous rock under greater than atmospheric pressure. Formation rocks have widely varying permeability and porosity and are generally categorized as sandstones, shales, and carbonates. The permeability of any given hydrocarbon-bearing formation correlates with how fast gas and/or oil may flow through the formation. The porosity of the formation correlates with the volume of gas or oil the formation may hold. Thus, an understanding of a formation's permeability and porosity is important for formulating well completion and production strategies for the formation. Various methods have been used for estimating permeability and porosity. Unfortunately, each method has its disadvantages; a common disadvantage concerns imprecision and difficulty in dealing with low permeability and porosity formations.
An instrument known as a core-permeameter has been used for non-destructive measurement of rock permeability. For a description of such a device see Chandler et al., U.S. Pat. No. 4,864,845. A permeameter is generally constructed of a narrow elastomer tube connected to a compressed gas source. The elastomer is pressed with a controlled force against the cylindrical, clean rock surface. A gas under a known pressure is forced from one end of the tube through the rock's pores. A flow meter measures the gas flow rate. The permeability of the sample is calculated from the flow rate and the applied pressure. The gas flow rate is estimated by a series of flow meters or orifice tubes which are selected to accurately cover a wide range of possible rates. An estimate of the permeability may be obtained by calibrating the mini-permeameter flow rate for various core plug samples of known permeability. On-site field operation of permeameters, however, has been a laborious task prone to frequent error. Thus, to obtain the permeability of a rock formation in situ using a permeameter, measurements are made at multiple sites at spaced intervals in an array or grid. Although the sensing of permeability occurs rapidly at each test site, the overall process requires a considerably greater amount of time for leveling the instrumentation, monitoring the flow rate, adjusting pressure, and recording the field measurements. Also, a bulky cylinder or an air compressor is generally needed to supply the relatively large amount of air required for multi-site testings.
In situ measurements of rock formations have also been made by a well test method, which involves monitoring changes in the pressure of a borehole as fluid is pumped out. One disadvantage of this technique is that only an average permeability is obtained; details on the permeability of heterogenous structures within the formation remain undefined. Furthermore, actual well production often does not correspond to forecasts.
Another commonly used method has involved extracting a core plug from the formation. The plug is then placed in a rubber sleeve known as a Hassler sleeve, and is sealed in place by a confining pressure applied to the outside of the sleeve. A pressure difference is applied across the length of the plug to induce flow through the plug. The rate of flow and a pressure difference are measured. Permeability is then computed by a mathematical formula known as Darcy's law. This approach is described, for example, in Freemann et al., U.S. Pat. No. 4,555,934 and Jones et al., U.S. Pat. No. 4,573,342. Although this approach allows for more detailed studies of formation permeability, it is very time consuming and sometimes not feasible, particularly on low permeability samples. Moreover, it does not measure permeability in situ, and it is destructive to samples. Furthermore, a porosity determination requires separate testing.
An x-ray CT or CAT scan imaging technique using xenon gas has also been suggested generally for determining porosity distribution in a whole core sample. This imaging technique has not been useful for determining permeability and required the use of a CT scanner facility.
Conventional preparation and measurement techniques are known to yield inaccurate estimates of a formation's permeability and porosity. For instance, core preparation techniques can alter a core sample and critically affect the ultimate determination of its permeability and porosity. For example, prepared cores often are exposed, dried, and treated with solvents. Further, some conventional core study techniques use a plug that is drilled from a standard whole core sample. During the drilling process, liquid nitrogen or other fluid may be applied to the core sample, and thereby alter the intrinsic nature of the sample. Consequently, core measurements made under current techniques all too often do not accurately portray a formation's native permeability or porosity due to sample alteration.
In general, conventional techniques lack the sensitivity to measure very low permeability formations. These techniques are mainly suitable for formations whose permeability ranges from millidarcies to darcies, such as sandstones. Shale, however, is a much tighter formation rock, whose permeability typically is in the microdarcies to nanodarcies range.
In addition to the above inaccuracies, other drawbacks exist in conventional methods. For example, it is very difficult, if not impossible, to concurrently measure porosity (gas storage volume), diffusivity and permeability using conventional methods. Moreover, many of the currently known techniques, particularly those used to test shales, destroy the samples, leaving nothing for use in further types of testing.